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IOCL Training Report

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IOCL Training Report

  1. 1. INDIAN OIL COPORATION LIMITED Summer Training Report Submitted By : NARENDRA SINGH CHOUDHARY Chemical Engineering Birla Institute of Technology Mesra, Ranchi
  2. 2.  Introduction  Atmospheric & Vaccum distillation (AVU)  Fludized catalytic cracking unit (FCCU)  Continues catalytic Reforming unit (CCRU)  Merox Unit  Propylene recovery unit (PRU)  Bitumen blowing Unit (BBU)  Diesel hydro desulphurization unit (DHDS)  Diesel hydro treatment unit (DHDT)  Once through hydro cracker unit (OHCU)  Hydrogen generation unit (HGU)  Amine recovery unit (ARU)  Sulfur recovery unit (SRU)  Motor spirit quality unit (MSQU)  Prime G  Process Flow of Mathura Refinery
  3. 3. ABOUT Mathura Refinery, the Sixth refinery of Indian Oil Commissioned in 1982 with a capacity of 6.0 MMTPA to meet the demand of petroleum products in north western region of the country. Refinery is located 154KM away from Delhi. The major secondary unit provided were Fluidised catalytic cracking unit (FCCU), Vis-breaker unit (VBU), and Bitumen Blowing unit (BBU). A Diesel hydro desulphurization unit (DHDS) commissioned in 1999 for production of HSD with low sulfur content of 0.25% wt (max). with the commissioning of Once Through Hydro Cracker unit (OHCU) in july 2000, capacity of Mathura Refinery was increased to 8.0 MMTPA. Diesel hydro-treating unit (DHDT) & MS quality upgradation unit (MSQU) was installed with world class technology from UOP in 2005 for production of Euro-III grade HSD & MS w.e.f. For upgrading environment standards, old Sulphur Recovery units (SRU) were
  4. 4. replaced with new sulphur Recovery units with 99.9% recovery in the year 1999. Products Indane Gas Auto Gas Natural Gas Petrol/Gasoline Diesel/Gas oil ATF/Jet fuel SERVO lubricants & greases Marine Fuels & Lubricants Kerosene Bitumen. Indian OIL is not only the largest commercial enterprise in the country it is the flagship corporate of the Indian Nation. Besides having a dominant market share, Indian oil is widely recognized as India’s dominant energy Brand and customers perceive Indian oil as a reliable symbol for high quality products and services.
  5. 5. Benchmarking quality, quantity and service to world class standards is a philosophy that Indian Oil adheres to ensure that customers get truly global experience in India. Our continued emphasis is on providing fuel management solutions to customers who can then benefit from our expertise in efficient sourcing and least cost supplies keeping in mind their usage patterns and inventory management. Retail Brand template of Mathura refinery are XtraCare(urban), Swagat(highway) and Kissan Seva Kendras(rural) are widely recognized as pioneering brands in the Petroleum retail segment. Indian Oil;s leadership extends to its energy brands Indane LPG, Servo Lubricants, Autogas LPG, XtraPremium Banded Petrol, Xtramile Branded Diesel, XtraPower Fleet card, Indian Oil Aviation and XtraRewards cash customer loyalty programme.
  6. 6. OIL Movement And Storage (OM&S) Oil movement and storage (OM&S) having two sub division OM&S1 and OM&S2. OM & S 1 Functions of OM&S 1  Receipt storage, accounting preparation and supply of crude oil to distillation units.  Supply of feeds to secondary processing units.  Blending of intermediate products.  Supply of intermediate fuel oil to units.  Measurement of petroleum products gauging sampling etc.  Oil accounting.  Dispatch of finished products. Products LPG+ Propylene - 3.15% Light Aromatic Naphtha- 4.77% Motor Spirit (1%) -8.33% Motor Spirit (3%) -3.97% Light Distillates Aviation Turbine Fuel -6.35% Superior Kerosene Oil -6.80% High Speed Diesel (.05% S)-13.61% High Speed Diesel (.25% S)-27.60% Middle Distillates -(54.54%) Total Distillates-(74.76%)
  7. 7. Furnace Oil -7.59% HPS/RFO-7.42% Bitumen-6.09% Sulphur-.5% Heavy Ends ISD-0.1% Gross Fuel Loss-6.64% Natural Gas-2.90% Net Fuel & Loss -3.74% The products produced by blending are motor spirit (88octane and 93 octane) high speed diesel (low sulphur and high sulphur),light diesel oil(LDO). OM&S 2 Waste water,oily water &oil spillages from pump.slabs & tank farmsis brought to the effluent treatment plant where oils is separated and is pumped to slop tanks. Storage Tanks For Different Products Naptha (101-104,123&124) Aviation Turbine Fuel (301-305) Superior Kerosene Oil (401-405) Diesel (501-509&513) Heavy Vaccum Gas Oil (851-853&503) Vaccum Slop (707&708) Furnace Oil (703-712) Crude Tank (001-006)&(007-008) Different pipelines to dispatch the products MJPL (Mathura Jalandhar Pipe lines) MBPL (Mathura Bharatpur Pipe lines) MTPL (Mathura Tundla Pipe lines) MMT (Mathura Marketing Terminal) GANTRY (Tank Wagon Loading)
  8. 8. Different types of tanks used to store products Fixed Roof Tank -used for storage of black oil, diesel, FO Floating Roof tank – used for storage of light products like, MS Naphtha ,SKO. Floating cum fixed roof tank - used for storage of ATF
  9. 9. Atmospheric and Vaccum Distillation Unit (AVU) The crude distillation unit was designed for desalting and primary distillation of light Arabian crude and North Rumalia mixture in the proportion of 1:1. The nominal designed capacity of the unit was 6MMTPA of the above crude on mixture. However the designed provided a possibility of processing 7MMTPA of crude of containing 2% weight of gas. Process calculation, sizing of vessels and equipment was made for the same. The unit has been revamped in different stages to raise its capacity and to process different types of crude including indigenous crude from Bombay High. Subsequent to these revamps, the nominal capacity of the unit stands at 8 MMTPA for processing imported Middle East crude and 7MMTPA for processing Bombay High. Based on 50:50 processing of imported and BH crudes in blocked out operation, the nominal capacity of the unit stands at 7.5 MMTPA. The unit has been designed to produce the following cuts: LPG To be sent to Merox treating unit
  10. 10. DESCRIPTION OF PROCESS FLOW SCHEME: FEED SUPPLY: crude is stored in eight storage tanks (six having a nominal capacity of 50,000 m3 each and remaining two are of 65,000m3 each). Booster pumps located in the off-sites are used to deliver crude to the unit feed pumps. Filters are installed on the suction manifold of crude pumps to trap foreign matter. For processing slop, pumps are located in the off site area which regulate the quantity of slop into the crude header after filters. Provision to inject proportioned quantity of demulsifier into the unit crude pumps suction header with the help of dosing pump is available. FEED PREHEAT (PRE-DESALTER) CIRCUIT: Crude oil from feed pumps is charged to heat exchangers in two parallel streams. DESALTING: Desalting is a purification process used for the removal of salts, inorganic particles and residual water from crude oil and thereby reducing corrosion and fouling of equipments. These impurities are brought along with the residual water content of the crude oil. Water drops ordinarily are so small that simple gravity settling is very poor .in an oil pool, the molecules that are least similar to the bulk of oil are subjected to less intermolecular forces. Being less attracted to the inner body of the oil, the exceptional material will be rejected to an inter-face of the oil/water drops. Such rejected surface active materials comprise a physical barrier that prevents water drops from getting close enough to bring about coalesce. Before the drops can coalesce the stabilizer film must be reduced in thickness, tenacity and therefore ruptured. The electric field is a powerful tool for overcoming the resistance of stabilizing films. The collision and coalescence of drops is accomplished by an induced dipole attraction between them. As the droplets then approach each other, the force between them becomes very great. The stabilizing films are squeezed between the drops and coalescence is rapid. The large water droplets produced fall through the oil phase at a
  11. 11. faster rate. This desalting process consists of three main stages, viz. heating, mixing and settling.Crude oil is heated to 125-135 °C in the pre-desalter heat exchanger train. Water is injected under flow control upstream of mixing valves. Provision is given at crude pumps suction also to facilitate break-up of tightly bound oilwater emulsion. Brine outlet from the desalters is cooled in air cooler and water cooler before final disposal. Desalter pressure is controlled between 11-12 kg-12 kg/cm2 by a conyrol valve located at the discharge end of the crude feed pumps. POST DESALTER CRUDE PREHEATING: Desalted crude from desalter is pumped by post desalter pumps into streams going through a second train (two in parallel) of heat exchangers. Downstream of the exchangers trains, crude oil streams combine to average out the temperature. Normal preheat temperature is in the range of 230-250 °C. FIRED HEATERS: the preheated crude is further heated and partially vaporized in three parallel tubular heaters. Each furnace is four pass heater with air preheater. Each furnace is provided with 14 burners capable of firing FO and FG, either fully or partially. Convection section has 8 rows of tubes with 8 tubes in each row. Two rows of shock tubes just above the radiant section are plain tubes with out studs. In the convection section 4 studded tubes are for the service of superheating MP stream for strippers. The radiant box has 21 tubes in each pass. Convection zone had 12 rotary and 12 retractable soot blowers in two rows. AIR PREHEATER SECTION: To recover waste heat from flue gases of CDU and VDU furnaces four identical parallel stationary air preheater units are provided and installed in parallel. At APH cold combustion air will pick up heat flue gas poat tobeme routed to the burner could to the burners for efficient combustion. Three FD fans each capable of 55% of full load are provided with SCAPH in there discharge to heat the air unto 45 °C. the combustion air requirement of each heater is controlled by individual FICS damper located in the air duct to the respective
  12. 12. furnace. Load on the fans is varied by regulating the inlet guide vances. Heaters are provided with slain temp O2 analyzer and draft gauges. Furnaces are provided with different trip logic to save the equipments under different abnormalities. CORROSION INHIBITOR: A solution of corrosion inhibitor in light hydrocarbon is required to be properly dispersed in vapor stream to combat corrosion of the overhead system. Most of the inhibitor is active in specific ranges closes to neutral. DEMULSIFIER: the injection rate should be around 6-8 ppm on crude.
  13. 13. Fluidized Catalytic Cracking Unit (FCCU) Objective: To convert Heavy Vacuum Gas Oil to valuable distillates like LPG, Gasoline, Diesel by catalytic cracking in fluidized bed. Feed: VGO/RCO/VR/Hydrocracker Bottom. Catalyst: Silica & Alumina Zeolite Structure. FCCU Product Yields: Sl. No. Products wt% 1 Gas 2.3 2 LPG 14.7 3 Gasoline 41.3 4 HN 21.3 5 LCO 11 6 HCO 0 7 CLO 10.9 8 Coke 4 Operating conditions:  Temperature range : 490-550 deg C  Pressure : 2-3 kg/cm2 System Description:
  14. 14. In the newer designs for Fluid Catalytic Cracking Unit, cracking takes place using a very active zeolite-based catalyst in a short-contact time vertical or upward sloped pipe called the "riser". Pre-heated feed is sprayed into the base of the riser via feed nozzles where it contacts extremely hot fluidized catalyst at 1230 to 1400 °F (665 to 760 °C). The hot catalyst vapourizes the feed and catalyzes the cracking reactions that break down the high molecular weight oil into lighter components including LPG, gasoline, and diesel. The catalyst-hydrocarbon mixture flows upward through the riser for just a few seconds and then the mixture is separated via cyclones. The catalyst-free hydrocarbons are routed to a main fractionator for separation into fuel gas, LPG, gasoline, light cycle oils used in diesel and jet fuel, and heavy fuel oil. During the trip up the riser, the cracking catalyst is "spent" by reactions which deposit coke on the catalyst and greatly reduce activity and selectivity. The "spent" catalyst is disengaged from the cracked hydrocarbon vapours and sent to a stripper where it is contacted with steam to remove hydrocarbons remaining in the catalyst pores. The "spent" catalyst then flows into a fluidized-bed regenerator where air (or in some cases air plus oxygen) is used to burn off the coke to restore catalyst activity and also provide the necessary heat for the next reaction cycle, cracking being an endothermic reaction. The "regenerated" catalyst then flows to the base of the riser, repeating the cycle. The gasoline produced in the FCC unit has an elevated octane rating but is less chemically stable compared to other gasoline components due to its olefin profile. Olefins in gasoline are responsible for the formation of polymeric deposits in storage tanks, fuel ducts and injectors. The FCC LPG is an important source of C3-C4 olefins and isobutane that are essential feeds for the alkylation process and the production of polymers such as polypropylene. In this process Heavy Gas Oil cut (Raw Oil) from Vacuum Distillation Section of AVU is catalytically cracked to obtain more valuable light and
  15. 15. middle distillates. The present processing capacity of the unit is about 1.48 MMT/Yr. It consists of the following sections:  Cracking section  Catalytic section,  Fractionation section  Gas concentration section.  CO boiler The unit is designed to process two different types of feed i.e. Arab Mix HVGO and Bombay High HVGO. Significance of Gas concentration section: In Gas con section the separation of LPG and stabilization of naphtha is achieved in steps as follows: The overhead gas is compressed by WGC to about 13 kg/cm2 . The LPG component in the compressed gas is absorbed by overhead naphtha in the absorber and send to stripper. The lighter ends C1 and C2 are stripped off and the stripper bottom is send to debutanizer.
  16. 16. The debutanizer separates the LPG and stabilize the naphtha. Key aspects of Operation and Maintenance: Catalyst circulation is established by fluidization. Handling of hydrocarbon and air side by side at very high temperature (500-700o C). Reactor and regeneration section is separated by delicate pressure balance. Coke deposited on the catalyst is burned off in regenerator at 650 deg c. Separation of fine catalyst in hydrocarbon vapoursand in flue gas by cyclones. Erosion is a common phenomena in Cyclone and slide Valves.
  17. 17. Continues Catalytic Reforming Unit (CRU) Objective: To Upgrade the Naphtha to High Octane MS Component (Reformate). Feed: 85-160 Deg C cut Naphtha / Visbreaker Naphtha Catalyst: Ni-Mo Oxides for NHTU Reactor Pt-Sn or Re for Reforming Product Yields: Sl. No. Products wt% 1 Motor Spirit 92.6 2 Hydrogen rich gas 6.8 3 LPG 0.55 Operating Conditions:  Temperature range: 490-540 C  System Pressure: 2.0 -30 kg/cm2 A catalytic reforming process converts a feed stream containing paraffins, Olefins and naphthene to aromatics. The product stream of the reformer is generally referred to as reformate. Reformate produced by this process has a very high octane rating. Significant quantities of hydrogen are also produced as a by-product. The whole CRU can be divided into three subunits as:  Naphtha Splitting Unit (NSU)  Naphtha Hydro-treater Unit (NHU)  Catalytic Reforming Unit NAPHTHA SPLITTING UNIT
  18. 18. This unit has been designed to split SR naphtha (144 MT/hr for BH and 95 MT/hr for AM) to C5-80 o C and 80-115 o C cut. Due to the restriction on Benzene content in the final product (motor spirit), the IBP of the heavier cut is raised to approximately 105 o C. NSU can be operated with naphtha directly from AVU (hot feed) and from OM&S (Cold feed), it can also be operated using both the feed simultaneously. For removal of benzene, the gasoline from storage tanks and CDU is sent to a column, containing 40 valve trays, which is called naphtha splitter. The bottom product of naphtha splitter is sent to the NHU. NAPHTHA HYDROTREATER UNIT The purpose of Naphtha hydrotreater is to eliminate the impurities (such as sulphur, nitrogen, halogens, oxygen, water, olefins, di-olefins, arsenic and metals) from the feed that would otherwise affect the performance and lifetime of reformer catalyst. This is achieved by the use of selected catalyst (nickel, molybdenum) and optimum operating conditions except for water, which is eliminated in stripper. In this unit, the naphtha coming from the NSU is mixed with H2 which comes from the reforming unit. This mixture is heated to 340 O C in the furnace and then passed to the hydrotreater reactor at a pressure of 22 kg/cm2 . In the reactor, there are two beds of catalyst. In one bed, the unsaturated hydrocarbons are converted to saturated hydrocarbons and in the second bed impurities like N, S, and O are converted to NH3, H2S and H2O respectively. The effluent of the reactor is sent to stripper section to eliminate the light end, mainly the H2S and moisture from the reformate feed. The light gases from the top of stripper are sent to amine wash unit. There is a reboiler attached to the bottom of the stripper, which maintains the heat requirement. The bottom product of the stripper is either sent to storage or the reforming unit.
  19. 19. REFORMING UNIT Feed for the Reforming unit (94 m3 /hr at 14 kg/cm2 and 110 o C) is received directly from hydrotreater stripper after heat exchanger. The filters must be provided for the protection of the welded plate exchanger. Feed is filtered to remove any foreign particles. At the D/S of the feed filter, chloriding agent and water injection are done. CCl4 solution of 1% in reformate is dosed by pump. Dosing @ 1 ppm wt CCl4 in feed is done when continuous regeneration unit is down. Water injection (not on regular basis) is done to maintain Cl-OH equilibrium on the catalyst when regenerator is out of service. Feed mixed with recycle H2 stream gets preheated in PACKINOX exchanger from 91o C to 451o C by the effluent from 3rd Reactor which gets cooled down from 497o C to 98o C. Due to the endothermic nature of the reforming reactions, the overall reforming is achieved in stages with inter stage heater provided to raise the temperature. There are three Reactors (15R-1, R-2 & R-3) each provided with reaction heater.
  20. 20. Merox Unit (Mercaptan Oxidation) Mercaptans are undesirable in the final products because it effects their stability, sulfur content, odour etc. Objective: Chemical treatment for conversion of Mercaptans to di- sulphides. Feed: ATF, Gasoline, VB Naphtha and LPG. Chemical reactions: RSH + 1/4 O2 = ½RSSR + ½H2O The MEROX process efficiently and economically treats petroleum fractions to remove mercaptan sulfur (MEROX extraction) or to convert mercaptan sulfur to less-objectionable disulfides (MEROX sweetening). This process can be used to treat liquids such as liquefied petroleum gases (LPG), natural-gas liquids (NGL), naphtha, gasoline, kerosene, jet fuels, and heating oil. It can also be used to treat gases such as natural gas, refinery gas, and synthetic gas in conjunction with conventional pre-treatment and post-treatment processes. Straight-run LPG, gasoline and kerosene fractions obtained from atmospheric distillation may contain hydrogen sulfide and mercaptans, the extent of which mainly depends upon the type of crude processed. Similar products from secondary processes such as FCC also contain hydrogen sulfide and mercaptans to a greater degree compared to straight-run products. Hydrogen sulfide is corrosive and should be removed in order to meet specifications on corrosion rate. The specification for LPG, gasoline, Kerosene and ATF include copper strip corrosion test which is a measure of rate of corrosion on copper containing materials. Mercaptans are substances with obnoxious odor and, therefore, in order to handle and store them, mercaptan level will have to be brought down to an acceptable odor level. The
  21. 21. specifications of above products include 'Doctor Test' which must be negative and is generally related to the extent of mercaptan present. Hydrogen-sulfide can be easily removed by washing with dilute caustic solution. However, for reducing the mercaptan level many processes are available like:  Strong alkali-wash  Copper sweetening  Doctor sweetening  MEROX process  Hydro desulphurization Alkali-wash is effective only if low molecular weight mercaptans are involved. Hydro desulphurization is normally employed only if reduction of total sulphur level is also required. Both investment and operating costs are higher in case of hydro desulphurization. a) MEROX PROCESS DESCRIPTION The Merox process licensed by M/S Universal Oil Products Co., (UOP), USA, is for the chemical treatment of LPG, gasolene and distillates to remove mercaptans into disulphides. The removal of mercaptans may be either partial or full. The chemical treatment is based on the ability of Merox catalysts to promote the oxidation of mercaptan to disulphide using air as the source of oxygen. The overall reaction is as follows: 2RSH + 1 /2O2 -> RSSR + H2O The oxidation is carried out in the presence of an aqueous alkaline solution such as either sodium hydroxide or potassium hydroxide. The
  22. 22. reaction proceeds at an economical rate at normal rundown temperature of refinery streams. Low molecular weight mercaptans are soluble in caustic solution and therefore when treating LPG and light gasoline fractions, the process can be used to extract mercaptan to the extent, they are soluble in caustic. Extraction of mercaptan reduces the sulphur content of the treated product. Alternatively mercaptans can be converted to disulphides without removing any sulphur from the treated stock in which case the operation is referred to as sweetening. In the treatment of heavier boiling fractions such as heavy naphtha and kerosene only sweetening is possible.  MEROX PROCESS EQUIPMENT: In order to understand the function of various Merox process equipment. the equipment can be broadly divided into following sections : 1. Pretreatment for removal of hydrogen sulphide and naphthenic acids, if present. The method varies with properties and conditions of feedstock and in some cases may not be required. 2. Extraction section where required, for removal of caustic soluble mercaptans and thus reduce sulphur in the treated product. 3. Sweetening for conversion of mercaptans to disulphides. For a given capacity plant, the Merox reactor size can vary depending on the case of sweetening due to the type of mercaptans present and also on product requirement. 4. Post-treatment to remove caustic haze and to control properties not affected by Merox process. Hence post-treatment needed
  23. 23. depends on products, utilisation and type of contaminants present in the feedstock. 5. Taking each section in turn, function of each equipment can be described.  PRETREATMENT Petroleum fractions may contain hydrogen sulphide and stocks boiling higher than 180°C may also contain naphthenic acids. Hydrogen sulphide is not a catalyst poison as such, but will dilute the caustic containing Merox catalyst by reacting with caustic. Further it blocks some of the catalyst activity sites slowing down the normal reaction and also consumes part of the oxygen available. Hence, it is recommended that hydrogen sulphide is removed by washing with dilute alkali solution before the distillate is sent to reactor for treatment. Naphthenic acids also interfere with treating operations and must be removed prior to treatment. The reactor contains caustic and if naphthenic acids are not remove they form sodium naphthenates which coat the catalyst and block the pores. For removal of napthenic acids, the procedure used is to wash with dilute caustic. Dilute caustic is used so as to avoid formation of emulsions. There could, however, be some carry-over of haze depending on the acidity of stock treated. The haze can easily be removed by coalescing through a sand filter. Feedstocks, where carry-over of water from distillation units can be expected must be passed through a coalescer for removal of suspended water prior to caustic wash, which would otherwise dilute the caustic used for pretreatment.  EXTRACTION SECTION
  24. 24. As previously stated, low molecular weight marcaptans are caustic soluble and can easily be removed by washing with caustic in a counter current tower. Improved extraction is favored by:  Low temperature.  High concentration of caustic.  Lower molecular wt. of mercaptans Type of mercaptans, viz. normal mercaptans are easily extractable, tertiary mercaptans least extractable and secondary being in between. The mercaptan enters the caustic solution and reacts as follows: RSH + NaOH <-> NaSR + H2O This is being a reversible reaction the degree of completion of reaction is governed by normal equilibrium laws. The sodium mercaptide is readily oxidised to disulphide in the presence of Merox catalyst as shown : 2NaSR + l /2O2 + H2O -> 2NaOH + RSSR This is not a reversible reaction and the reaction rate is speeded up by:  Raising the temperature.  Use of excess air.
  25. 25.  Increasing the intimacy of contact.  Increasing the catalyst concentration. The oxidation of mercaptides is carried out in oxidiser in the presence of merox catalyst. The disulfides oil, which is formed, separates out from caustic as it is insoluble in caustic. Caustic can be reused for extraction. The presence of Merox catalyst in extraction caustic does not however, affect the amount of mercaptans extracted. and extraction is dependent only on parameters explained earlier .  SWEETENING Sweetening can be defined as conversion of mercaptan sulphur present in a hydrocarbon stream to disulphide sulphur without actually reducing sulphur content of treated stock. The sweetening process is based on the ability of Merox catalyst to promote the oxidation of mercaptans to disulphides using air as the source of oxygen. The reaction is as follows: RSH + NaOH <-> NaSR + H2O 2NaSR + l /2O2 + H2O -> 2NaOH + RSSR As can be seen from reactions, the oxidation is carried out only in the presence of alkali solution. The Sweetening can be accomplished either in solid bed sweetening, where the hydrocarbons and caustic are simultaneously controlled over a solid support impregnated with Merox catalyst.
  26. 26. Liquid-liquid sweetening where hydrocarbon, air and caustic containing Merox catalyst, air simultaneously controlled in a mixer. Solid bed sweetening consists of a reactor, which contains a bed of activated charcoal impregnated with Merox catalyst and kept wet with caustic solution. Impregnation of catalyst on bed is achieved by dissolving the catalyst with ammonia solution and pumping ammonia solution over charcoal. Air is injected ahead of reactor and in the presence of merox catalyst the mercaptans are oxidised to disulphides. The reactor is followed by a settler which serves as reservoir of caustic. Caustic is intermittently circulated from the settler over the catalyst bed to wet the charcoal. For liquid-liquid sweetening, the most common type of mixer used is the orifice plate mixer, which is a vessel, fitted with a series of plates with orifices. The vessel provides adequate residence time and the orifice plates create enough turbulence to bring about the intimate contact between hydrocarbon, caustic, catalyst and air. The problem of accomplishing liquid-liquid sweetening is one of getting the difficulty soluble mercaptans into the caustic phase for sufficient time to permit their oxidation. The higher the molecular weight or the more highly branched the mercaptan is, the more difficult it is to accomplish necessary mixing. Hence heavy gasoline and Kerosene may have to be treated using fixed bed reactor.  POST TREATMENT The product from the merox reactor will at times contain caustic haze. Post treatment is required if the product is to go to storage, clear and bright. In most cases provision of caustic settler and sand filter is adequate to remove caustic haze. However, for treatment of ATF, which has to meet stringent specification caustic must be removed by
  27. 27. water wash after caustic settling. Water wash removes entrained caustic as well as water soluble surfactants, Water wash is followed by a salt filter to remove entrained water and part of the dissolved water. This may be followed by clay filter to remove copper and water insoluble surfactants, if present in feed.  MEROX CATALYSTS There are two types of Merox catalyst, each one being used for specific service. Catalyst FB is to be used on units equipped with solid bed sweetening reactors. Catalyst WS is used for liquid-liquid sweetening in mixers. This is a caustic dispersible catalyst. This is also used for oxidation of extraction caustic in oxidisers.
  28. 28. Propylene Recovery Unit (PRU) Objective: To produce propylene from cracked LPG. Feed: Cracked LPG from FCCU. Brief Description of Process: Propylene Recovery Unit at Indian Oil Corporation Limited, Mathura is designed to produce Polymer grade propylene from cracked LPG, which will be supplied from FCCU. It is a mixture of Propane, Propylene, Butane, Butylene with some amounts of C2 & C5 hydrocarbons. The process package is supplied by EIL. Production capacity of Propylene is 34,460 MTA from 1,44,000 MTA of cracked LPG available from FCCU (based on FCCU capacity of1.3 MMTPA considering 345 days/year operation). Purity of Propylene produce will be 99.7% vol. Turn down ratio of the unit is 40%. The unit is designed to recover 97.5% of propylene in LPG feed for typical case. Process Flow Sections: For the purpose of description unit has been divided into following major sections: 1) Feed surge drum and depropanizer section i.e.separation of C4’S from C3’S. 2) COS Hydrolyser 3) De-ethanizer section i.e. separation of low boiling hydrocarbons from C3’S. 4) Propane-Propylene splitter section. 5) H2S removal from propylene.
  29. 29. 6) Water adsorption section for propylene drying. Product Yields: Sl. No. Products wt% 1 Propylene 14.6 2 LPG 85.4 Bitumen Blowing Unit (BBU) Objective: To Produce different grades of Bitumen by air blowing of vacuum residue at high temperature. Bitumen is colloidal solution of asphaltenes and high molecular gums in the medium formed by oils and low molecular gums. Feed : Vacuum Residue Typical Operating Conditions of Bitumen Blowing Unit:  Temperature Range : 230-260 Deg C  Pressure: 0.5 kg/cm2 Product Quality: Sl. No. Products wt% 1 Off-Gas 0.86 2 Recovered Liquid Cut 0.26 3 Finished Bitumen 98.99
  30. 30. Diesel Hydro Desulfurization Unit (DHDS) DHDS (Diesel hydro desulphurization unit) is set up for the following purposes:  A step towards pollution control  To produce low sulphur diesel (0.25 w/w %) as per govt. directive w.e.f. Oct. 1999. Feed consists of different proportion of straight run LGO, HGO, LVGO and TCO. Mainly two proportions are used:  74% SR LGO, 21% SR HGO, 5% SR LVGO  48% SR LGO, 24% SR HGO, 8% SR LVGO, 20% TCO The DHDS unit treats different gas oils from various origins, straight run or cracked products. The feed is a mixture of products containing unsaturated components (diolefins, olefins), Aromatics, Sulfur compounds and Nitrogen compounds. Sulfur and nitrogen contents are dependent upon the crude. The purpose of DHDS Unit is to hydro-treat a blend of straight run gas oil and cracked gas oil (TCO) for production of HSD of sulfur content less than 500 ppm wt. The Hydrodesulphurization reaction releases H2S in gaseous hydrocarbon effluents. This H2S removal is achieved by means of a continuous absorption process using a 25% wt. DEA solution. In addition to the desulphurization, the diolefins and olefins will be saturated and a denitrification will occur. Denitrification improves the product stability. The hydrogen is supplied from the hydrogen unit. Lean amine for absorption operation is available from Amine Regeneration Unit (ARU). Rich Amine containing absorbed H2S is sent to ARU for amine regeneration.
  31. 31. CATALYSTS Catalysts used for this process are HR-945 and HR-348/448.The HR-945 is a mixture of nickel and molybdenum oxides on a special support. Nickel has been selected because it boosts the hydrogenating activity. The HR-348 and HR-448 are desulphurization catalysts; it consists of cobalt and molybdenum oxides dispersed on an active alumna. Its fine granulometry and large surface area allow a deep desulphurization rate. Different catalysts based on Nickel and Molybdenum Oxide are used to enhance the rate of reactions. Products Yields: Sl. No. Products wt% 1 Off-Gas 1.36 2 Wild-naptha 1.04 3 Diesel 97.1
  32. 32. Diesel Hydro Treatment Unit (DHDT) Objective : To meet the EURO-III/IV diesel quality requirement (<350/50 ppmS) Feed : Straight run diesel / FCC diesel component/ Coker and Visbreaker diesel components. Catalyst : Ni-Mo oxides Products Yields: Sl. No. Products wt% 1 Off-Gas 2.65 2 wild-naphtha 2.8 3 Diesel 96.1 Wild naphtha feed from existing DHDS unit is processed along with DHDT wild naphtha in a stabilizer located inside DHDT battery limits for producing single naphtha product. Processes in DHDT:  Refining & hydrogenation: Removal of heteroatom (S, N2, O2) Saturation of olefins and dioelfins.  Hydrodesulfurization:
  33. 33. Hydrodesulfurization reactions are fast and take place in single step. Mercaptans: R-SH + H2 R-H + H2S Sulfides: R-S-R + 2H2 2R-H + H2S  Hydrogenation: Aromatic saturation & denitrification of heterocyclic compounds.  Hydrocracking: Hydroisomerisation & then cracking into lighter isoparaffins.  Metal removal  Coking
  34. 34. Once Through Hydro-Cracker Unit (OHCU) Hydrocracking is a extremely versatile catalytic process in which feed stock ranging from Naphtha to vaccum residue can be processed in presence of hydrogen and catalyst to produce almost any desired product lighter than feed. Thus if the feed is Naphtha it can be converted into LPG if feed is VGO it can produce LPG, Naphtha, ATF, Diesel. Process configuration Depending upon the feed quality, product mix desired and the capacity of unit, following process flow configuration can be adopted for hydrocracker.  Single stage – for 100% conversion  Two stage – for 100% conversion  Once through – for partial conversion of feed to products 60-80% In single stage, the unconverted material from fractionator, bottom is recycled to first reactor along with fresh feed. In two stage the unconverted material is routed separately to another reactor. Products of HCU LPG Stabilized light Naphtha Heavy naphtha ATF/SKO high Speed Diesel
  35. 35. Process Description In Hydrocracker the VGO feed is subjected to cracking in reactor over catalyst beds in presence of Hydrogen at pressure of 185Kg/cm2 and temperature from 365-441 C. the cracked products separated in fractionator. Light ends are recovered in Debutanizer column. The process removes almost all S and N from feed by converting them into H2S and NH3 respectively, thus the product obtained are free of sulfur and nitrogen compound and saturated. Therefore except for mild NaOH wash for LPG , post treatment is not required for other products. UNITS OF HCU  Make up hydrogen section  Reaction section  Fractionation section  Light ends recovery section Make up Hydrogen Compression section The makeup Hydrogen Compression section consist of three identical parallel compressor trains, each with three stage compression during normal operation two trains are in use and compress makeup hydrogen form a pressure swing adsorption (PSA) unit to reaction section the compressed makeup hydrogen is combine with hydrogen recycle gas in the reaction to form reactor feed gas. The makeup hydrogen compression section is also used to compress a mixture of nitrogen and air during catalyst regeneration.
  36. 36. Reaction section The reaction section contains one reaction stage in a single high pressure loop. Due to reactor weight limit of approximate 400 M Ton. The reaction section consists of two reactors in series. The hydro- treating & hydro-cracking reactions taking place in the reaction stage occurs at high temperature and pressure. A high hydrogen partial pressure is required to promote the hydro0cracking reaction and to prevent coking of the catalyst. An excess of hydrogen is recirculated in the reactor loop for reactor cooling to maintain a high hydrogen partial pressure and to assure even flow distribution in the reactors. Fractionation section It is used to separate reaction section products into sour gas, un- stabilized liquid naphtha, heavy naphtha, kerosene and diesel. Furthermore, bottom containing un-converted product servers as feed to the FCC unit or is sent to tankage. The sour gas and un-stabilized naphtha are sent to the light end section to make fuel gas, LPG and light naphtha. Light Ends Recovery section Light naphtha from the fractionator is sent to de-ethanizer, where gas are removed and sent to amine absorber where the H2S is absorbed in the Amine and H2S free fuel gas is sent fuel gas system. Rich Amine with dissolved H2S is sent to Amine Regeneration unit in sulfur recovery unit. The bottom of dethanizer is sent to debutanizer. For the recovery of LPG, LPG is taken out from the top and sent to treating section where it is washed with caustic for removal of H2S. the stabilized
  37. 37. naphtha from the bottom of the stabilizer is sent to hydrogen unit to produce hydrogen. OHCU FLOW SHEET
  38. 38. Hydrogen Generation Unit (HGU) Objective : To Meet the Hydrogen requirement for DHDS/DHDT/OHCU/ISOM/Reforming Units and Other Hydrotreaters. Feed : Natural Gas / Naphtha and Feed Catalyst : Co-Mo for Hydrotreater ZnO/K2Co3 for H2S and Chloride adsorber NiO for Preformer Ni for Reformer CuO for HT/LT Shift reactors Adsorbents(molecular sieves) for PSA Adsorbers HGU Product is 99.99% Pure H2 Operating Conditions :  Temperature range : 860-870 C  System Pressure : 20-38 kg/cm2 Even traces of sulphur is poison to Reformer Catalyst. Sulphur guard is provided to reduce feed sulphurto <50 ppb. Pre Reformer reduce the load on the reformer by converting the heavier molecules to methane at relatively lower temperature. The Shift reactor maximize the H2 production by Shift reaction (i.e. CO +H2O H2 +CO2).
  39. 39. Sophisticated process Interlocks are provided as reformer operates at very high temperature and it is prone to coking in absence of steam. Reformer furnace draft is critically controlled by variable frequency drive of FD/ID fan.
  40. 40. In IOCL mathura refinery there are two hydrogen generation units: HGU-I & HGU-II HGU-I: The Hydrogen plant is designed for production of 34,000 MTPY of Hydrogen. Process licensor for HGU is HTAS, Denmark. The plant is divided into 3 sections.  Desulphurization  Reforming  CO-Conversion FEED The hydrogen generation unit can be fed either by naphtha or natural gas. The naphtha feed is pressurized to about 35 Kg/cm2g by one of the naphtha feed pumps and sent to the desulphurization section. The pressurized feed is mixed with recycle hydrogen from the hydrogen header. The liquid naphtha is evapourated to one of the naphtha feed vapourizers. The hydrocarbon feed is heated to 380°-400 O C by heat exchange with superheated steam in the naphtha feed pre-heater. DESULPHURIZATION The desulphurization takes place in two steps. The first catalyst in the desulphurization system is a cobalt-molybdenum hydrogenation catalyst. R1 – S – R2 + 2H2 → R1 – H + R2 – H + H2S
  41. 41. Having passed the hydrogenation catalyst in the first reactor the hydrogenated process feed is sent to the sulphur absorbers. Here the H2S formed is absorbed by the ZnO absorption catalyst. ZnO + H2S → ZnS + H2O The concentration of sulphur leaving the absorbers shall be lower than 50 ppm. REFORMING SECTION: PRE-REFORMER The mixture of gas and steam (the process gas) is heated to approximately 490O C. The preheated process gas passes the pre- converter, where all higher hydrocarbons are converted into methane, hydrogen, carbon monoxide and carbon dioxide. TUBULAR REFORMER The pre-converted process gas is further preheated to approximately 650°C in the reformer feed preheat coil before it is sent to the tubular reformer containing 126 catalyst tubes maintained at desired temperature. The reformer effluent leaves the tubes at a temperature of approximately 930° C. HGU-II: The Hydrogen plant is designed for production of 74,000 MTPA of Hydrogen. Here also stem reforming of natural gas or naphtha is done to produce hydrogen. HGU-II has following processes:  Feed predesulfurization  Feed desulfurization
  42. 42.  Pre-reforming  Reforming  High Temperature shift Reaction  Low Temperature shift reaction HGU-II Furnace has top fired burners. HGU-II has 12 PSA Drums. Process: Asphaltic bitumen, normally called "bitumen" is obtained by vacuum distillation or vacuum flashing of an atmospheric residue. This is “straight run" bitumen. An alternative method of bitumen production is by precipitation from residual fractions by propane or butane- solvent de-asphalting. The bitumen thus obtained has properties which are derived from the type of crude oil processed and from the mode of operation in the vacuum unit or in the solvent de-asphalting unit. The grade of the bitumen depends on the amount of volatile material that remains in the product: the smaller the amount of volatiles, the harder the residual bitumen. The blowing process for bitumen preparation is carried out continuously in a blowing column. The liquid level in the blowing column is kept constant by means of an internal draw-off pipe. This makes it possible to set the air-to-feed ratio (and thus the product quality) by controlling both air supply and feed supply rate. The feed to the blowing unit (at approximately 210 0C), enters the column just below the liquid level and flows downward in the column and then upward through the draw-off pipe. Air is blown through the molten mass (280-300 0C) via an air distributor in the bottom of the column. The bitumen and air flow are countercurrent, so that air low in oxygen meets the fresh feed first. This, together with the mixing effect of the air bubbles jetting through the molten mass, will minimise the
  43. 43. temperature effects of the exothermic oxidation reactions, local overheating and cracking of bituminous material. The blown bitumen is withdrawn continuously from the surge vessel under level control and pumped to storage through feed/product heat exchangers. Air residue having boiling point 530o C (TBP) is obtained from North Rumaila crude. Air blowing of vacuum residue at high temperature considerably increases the contents of gums and asphaltenes at the expense of conversion of a portion of hydrocarbon into condensed oil. Bitumen is a colloidal solution of asphaltenes and associated high molecular gums in the medium formed by oils and low molecular gums. Asphaltene content in the bitumen influences its solidity and softening point. The higher the asphaltene content, the more solid is the bitumen. Gums increase bitumen binding properties and elasticity.
  44. 44. Amine Recovery Unit (ARU) INTRODUCTION : Diethanol amine almost saturated with H2S (rich amine) and received at battery limit from DHDS, FCC, OHCU unit is processed in unit ARU to separate out H2S and amine solution (lean amine), which is obtained as bottom product from ARU. H2S and other light components present in the rich amine are separated out as overhead product. PROCESS DESCRIPTION  AMINE FLASH DRUM The rich amine containing absorbed H2S and CO2 from amine absorber and LPG MEROX units enter the amine flash column at a pressure of about 5 kg/cm2 and temperature of 55O C. Height of flash column is approximately 11.4 in. and dia. = 500 mm at the top and 1600 mm at the bottom of section. Top section is packed with raschig rings. Rich amine at 5 kg/cm2 is flashed into the column to a pressure of 2.8 kg/cm2. The bottom section contains four single pass valve trays. Because of flashing, hydrocarbons in the amine get liberated, thereby reducing the quantity of hydrocarbons going with sour gas to sulphur unit, which spoils the catalyst.
  45. 45. The liberated hydrocarbons from the top of the column enter the flare header through a pressure control valve. The column top pressure is maintained at 2.8 kg/cm2. When column pressure rises, a valve opens and lets off the liberated hydrocarbons to flare and when pressure drops pressure valve opens for fuel gas (FG) to enter the column. A slipstream reflux of lean amine solution is fed into the top of column above the packing to reabsorb any H2S liberated during flashing from the bottom of the flash column.  REGENERATION In amine regeneration the rich DEA is stripped of its absorbed sour gases H2S and CO2 using steam. So regenerated amine can be reused in absorber. Amine reboiler is heated by LP steam. Steam strips off the absorbed H2S and CO2 present in the DEA solution. Reactions involved are: R2NH3S R2NH + H2S where R = CH3CH2OH The top temperature of regenerator is about 105o C and middle temperature is about 115 o C. Pressure is nearly 0.5 kg/cm2. The liberated sour gases leave the regenerator from the top and enter the overhead condenser where gases are cooled and steam is condensed to 45 o C. Sour gas from the reflux drum top goes to the sulphur recovery plant by the production of Sulphur. Reboiler has two compartments separated by a baffle. By heating the compartment DEA overflow above the baffles to the other compartments from where it flows to regenerator by gravity. The excess pressure drop is due to foaming of amine inside the column. So, antifoaming agent dosing is needed. Foaming is caused due to contamination of amine solution by condensed light hydrocarbons, fine suspended solids or surface-active agents.
  46. 46. A portion of cold lean amine is passed through charcoal filter to remove iron impurities due to corrosion and to a sand filter to absorb charcoal and sent to suction line of lean amine pump. Sulfur Recovery Unit (SRU) Objective: To Reduce the SO2 emission from the Refinery by recovering Sulphur from Amine Acid and Sour Gases produced during various Hydrotreating Process. Feed : Amine Acid gases and Sour acid gases Operating Conditions:  Temperature Range : 195-320 Deg C  Pressure: 0.56 kg/cm2(g) Product Yield: Sl. No. Products wt% 1 Off-Gas 0.1 2 Sulphur 99.9 Chemical reactions in SRU: Claus Reactions The main reaction (PARTIAL OXIDATION) in the main burner is :
  47. 47. H2S + 3O2------> SO2+ H2O +heat The major part of the residual H2S combines with the SO2 to form sulphur, according to the equilibrium reaction : 2H2S + SO2< -------> 3S2+ 2H2O -heat By this reaction , known as the Claus reaction, sulphur is formed in vapour phase in the main burner and combustion chamber. Motor Spirit Quality Unit (MSQU) Objective : To Upgrade the Naphtha by increasing its Octane Number to Higher Octane/Low Benzene/Low Olefins MS Component (Isomerate) to Meet Euro III / IV MS Specifications. Feed: C5-85 Deg C cut Naphtha /FCC gasoline(70-90 deg C cut)/ Lt. Reformate Catalyst: Co-Mo for HydrotreatorReactor Pt for PenexReactor Ni Based for Methanation Processes:  Naptha hydrotreating unit  Reformate splitter unit
  48. 48.  Penex unit Operating conditions:  Temperature range : 126-145o C  System Pressure : 33.5 kg/cm2 Products Yield: Sl. No. Products wt% 1 Motor Spirit 90-91 2 LPG 10-11 MSQU process technology is used for production of blending stream of gasoline to meet stringent quality of MS w.r.t. benzene & aromatics content. Purpose of Naphtha hydro treating process: It is used to remove Penex catalyst poisons from light naphtha prior to charging to Penex process unit. UOP Naphtha hydrotreating process is catalytic refining process employing a UOP hydrotreating catalyst and a hydrogen rich gas stream to decompose organic sulfur, oxygen and nitrogen compounds contained in the naphtha fraction. In addition, hydrotreating removes organo-metallic compounds and saturates olefinic compounds. Organo-metallic compounds such as arsenic, lead & silicon compounds are known to be permanent poison to platinum containing catalysts. Purpose of reformate splitter:
  49. 49.  Split C6 & lighter species from the heavier reformate in the reformate splitter.  Overhead vapor from reformate splitter is then condensed and collected in reformate splitter receiver. This stream is mixed with stream from separator of NHT unitand sent as feed to Penex-DIH unit through sulfur guard. Prime G Unit Objective: Removal of sulfur from FCC gasoline with minimum octane loss to meet norms of EURO-IV in MS. Feed : FCC Gasoline Total Sulphur in Product: ≤100 ppmw Technology: Prime G Process:  Selective Hydrogenation Unit (SHU)  Gasoline Splitter Unit(GSU)  Hydro-desulphurization Unit (HDU) SHU Reactor: Feed comes from Heart cut of FCC. Only Diolefins are hydrotreated and light mercaptans are converted into heavy
  50. 50. mercaptans. Now this product is sent to splitter unit, where it is split into Light cut naphtha(LCN) & Heavy cut naphtha(HCN) Gasoline splitter Unit: splits the products from SHU reactor into LCN and HCN. HDS Unit: Olefin saturation is very limited and no aromatic hydrogenation occurs. Catalyst: Co-Mo based catalyst. Products yield: Sl. No. Products wt% 1 LCN 23 2 heart Cut 15 3 HCN 62
  51. 51. FLOW SHEET OF MATHURA REFINERY

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